In drilling a wellbore into the earth, such as for the recovery of hydrocarbons or minerals from a subsurface formation, it is conventional practice to connect a drill bit to the lower end of an assembly of drill pipe sections connected end-to-end (commonly referred to as a “drill string”), and then to rotate the drill string so that the drill bit progresses downward into the earth to create the desired wellbore. In conventional vertical wellbore drilling operations, the drill string and bit are rotated by means of either a “rotary table” or a “top drive” associated with a drilling rig erected at the ground surface over the wellbore (or, in offshore drilling operations, on a seabed-supported drilling platform or a suitably adapted floating vessel).
During the drilling process, a drilling fluid (also called “drilling mud”, or simply “mud”) is pumped under pressure downward through the drill string, out the drill bit into the wellbore, and then upward back to the surface through the annular space between the drill string and the wellbore. The drilling fluid, which may be water-based or oil-based, carries wellbore cuttings to the surface, but can also perform other valuable functions, including enhancement of drill bit performance (e.g., by ejection of fluid under pressure through ports in the drill bit, creating mud jets that blast into and weaken the underlying formation in advance of the drill bit), drill bit cooling, and formation of a protective cake on the wellbore wall (to stabilize and seal the wellbore wall).
Particularly since the mid-1980s, it has become increasingly common and desirable in the oil and gas industry to use “directional drilling” techniques to drill horizontal and other non-vertical wellbores, to facilitate more efficient access to and production from larger regions of subsurface hydrocarbon-bearing formations than would be possible using only vertical wellbores. In directional drilling, specialized drill string components and “bottomhole assemblies” (BHAs) are used to induce, monitor, and control deviations in the path of the drill bit, so as to produce a wellbore of desired non-vertical configuration.
Directional drilling is typically carried out using a downhole motor (also called a “drilling motor” or “mud motor”) incorporated into the drill string immediately above the drill bit. A typical downhole motor assembly includes the following primary components (listed in sequence, from the top of the motor assembly):                a top sub adapted to facilitate connection to the lower end of a drill string (“sub” being the common general term in the oil and gas industry for any small or secondary drill string component);        a power section operably connected to the top sub;        a drive shaft housing (which may be straight, bent, or incrementally adjustable between zero degrees and a maximum angle);        a drive shaft enclosed within the drive shaft housing, with the upper end of the drive shaft being operably connected to the power section; and        a bearing section comprising a bearing mandrel coaxially and rotatably disposed within a bearing mandrel housing, with an upper end coupled to the lower end of the drive shaft, and a lower end adapted for connection to a drill bit.The bearing mandrel is rotated by the drive shaft, which rotates in response to the flow of drilling fluid under pressure through the power section. The bearing mandrel rotates relative to the bearing mandrel housing, which is connected to the drill string (via the drive shaft housing and other housing sections forming part of the BHA) such that the bearing mandrel housing rotates with the drill string.        
Conventional downhole motor assemblies commonly include power sections incorporating either a “Moineau” drive system (i.e., a progressive cavity motor, comprising a positive displacement motor of well-known type, with a helically-vaned rotor eccentrically rotatable within a stator section) or a turbine-type drive system.
In one operational mode, a downhole motor may rotate the bit without concurrent rotation of the drill string; this is referred to as “slide drilling”. In another operational mode, the downhole motor may rotate the bit relative to the drill string in conjunction with rotation of the drill string by a top drive or rotary table.
In recent years, the available torque output of downhole motor power sections has continued to increase due to improved technologies and manufacturing capabilities, and is outpacing the torsional capacity of downhole motors. This trend appears likely to continue as increasingly higher torques are required for drilling through hard subsurface formation materials.
Such high torque requirements are straining the capabilities of conventional downhole motors, causing premature failures and unfavorable drilling conditions such as “stick slip” and “BHA whirl” (terms that will be familiar to persons skilled in the art). Due to the design characteristics of conventional drilling tools, increased reactive torque loads are being transferred through the drill string components, resulting in back-offs and fatigue failures.
For the foregoing reasons, there is a need for downhole motors that will allow the use of lower-torque conventional power sections to drill through hard subsurface materials while reducing the magnitude of reactive torque loads being transferred to the drill string.